Presentation:
Oil & Gas Law
Chapter 7: Royalty Clauses and Division Orders
Professors Wells
November 2, 2015
Royalty Clauses:
Southland Royalty Co. v. Pan American Corp.
Southland Royalty Co. v. Pan American Corp, 378 S.W.2d 50:
1.  Facts
1st To deliver to the credit of lessor, free of cost, in the pipe line to which they may connect their
wells, the equal one-eighth part of all oil produced and saved from the leased premises and 1/8 of
the net proceeds of potash and other minerals at the mine.
2nd To pay the lessor One Hundred Dollars, each year in advance for the gas from each well where
gas only is found, while the same is being used off the premises, and lessor to have gas free of cost
from any such well for all stoves and all inside lights in the principal dwelling house on said land
during the time by making their own connections with the well at their own risk and expense.
3rd To pay lessor for gas produced from any oil well and used off the premises at the rate of Fifty
and No/100 Dollars per year for the time during which such gas shall be used, said payments to be
made each three months in advance.
2.  Court reasoning
“We also think there is no serious question raised but that the words “mineral” or “minerals”
include gas.”
2 Model Lease Agreement:
Free Use of Gas
Paragraph 3
The royalties to be paid by Lessee are: . . . (b) on gas, including casinghead gas or other
gaseous substance, produced from said land and sold or used off the premises or for the extraction
of gasoline or other product therefrom, the market value at the well of one-eighth of the gas so
sold or used, provided that on gas sold at the wells the royalty shall be one-eighth of the
amount realized from such sale.
* * * *
Lessee shall have free use of oil, gas, coal, and water from said land, except water from Lessor’s
wells, for all operations hereunder, and the royalty on oil, gas, and coal shall be computed after
deducting any so used.
3 Royalty Clauses:
Cannon v. Cassidy
Cannon v. Cassidy, 542 P.2d 514:
1.  Facts
2.  Court reasoning
“[L]essee’s failure to pay royalty as provided by the lease will not give lessors sufficient grounds
to declare a forfeiture unless by the express terms of that lease they are given that right and power.
We note in passing that the overwhelming majority of jurisdictions which have considered this
issue are in accord.”
4 Royalty Clauses:
Model Lease Agreement
Paragraph 9
The breach by Lessee of any obligation arising hereunder shall not work a forfeiture or termination
of this lease nor cause a termination or reversion of the estate created hereby nor be grounds for
cancellation hereof in whole or in part. In the event Lessor considers that operations are not at any
time being conducted in compliance with this lease, Lessor shall notify Lessee in writing of the
facts relied upon as constituting a breach hereof, and Lessee, if in default, shall have sixty (60)
days after receipt of such notice in which to commence the compliance with the obligations
imposed by virtue of this instrument. After the discovery of oil, gas or other mineral in paying
quantities on said premises, Lessee shall develop acreage retained hereunder as a reasonable
prudent operator but in discharging this obligation it shall in no event be required to drill more
than one well per forty (40) acres of the area retained hereunder and capable of producing oil in
paying quantities and one well per 640 acres plus an acreage tolerance not to exceed 10% of 640
acres of area retained hereunder incapable of producing gas or other mineral in paying quantities.”
5 Royalty is a fractional share of production or revenues received from selling the production.
Example:
Royalty = 1/8th of oil and gas produced and sold. Here, royalty = 1/8th of price x quantity
•
•
•
•
By the contract price received for the gas sold from the lessor’s tract?
By the market value of similar oil or gas, sold by others?
By an index price (that is used to measure the market value at a hub)?
In kind?
•
•
•
•
•
“At the well”?
At the point of sale to an affiliate?
At the point of sale to the first non-affiliated, third party buyer?
At the point of delivery to [what facility– a pipeline, a processing plant, a market hub]?
At the tailgate of a gas processing plant?
•
•
•
•
Gas from a well only?
Casinghead gas from an oil well?
Oil?
Carbon dioxide and other gases? Sulfur?
•
•
•
When produced?
When produced and sold? Produced and sold and delivered?
When is the gas sold? It the gas sold under a long-term contract is signed to sell the gas at a fixed price?
•
•
E.g., under a “proceeds” or “amount realized” lease?
Under a “market value” lease?
6 Royalty Clauses: Market Value vs. Proceeds
Texas Oil and Gas Corp. v. Vela
Texas Oil and Gas Corp. v. Vela, 429 S.W.2d 866:
1.  Facts
“pay to lessor, as royalty for gas from each well where gas only is found, while the same is being
sold or used off of the premises, one-eighth of the market price at the wells of the amount so sold
or used”
2.  Court reasoning
“Instead of doing so, however, they stipulated in plain terms that the lessee would pay one-eighth
of the market price at the well of all gas sold or used off the premises. This clearly means the
prevailing market price at the time of the sale or use. The gas which was marketed under the longterm contracts in this case was not “being sold” at the time the contracts were made but at the time
of the deliver to the purchase. We agree with the Court of Civil appeals, therefore, that the
contract price for which the gas was sold by the lessee is not necessarily the market price within
the meaning of the lease.”
7 Royalty Clauses: Market Value vs. Proceeds
Exxon Corp. v. Middleton
Exxon Corp. v. Middleton, 613 S.W.2d 240:
Anuhuac Field
Annuhuac
Main Gas
Unit #1
1.  Facts
Middleton
Middleton
2.  Court reasoning
“Market value may be calculated by using comparable sales. Comparable sales of gas are those
comparable in time, quality, quantity, and availability of marketing outlets.”
8 Royalty Clauses: Market Value vs. Proceeds
Problem Set on page 7-22
Problem
Lessor Able and Lessor Baker have leased adjacent tracts to Bigg Oil. Bigg has erected a
processing plan on Able’s tract. Both leases have the typical bifurcated royalty clause:
“proceeds” royalties are paid on sales at the well and “market value at the well” royalties are
paid for sales off the lease.
The lessee sells all the gas from both Able’s and Baker’s tracts at the tailgate of the processing plant for
$2.20 per MCF. Processing costs amount to 20 cents per MCF.
(A)  What price is used to value Able’s royalty?
Answer: Bigg Oil has the plant on Able’s lease and sells the gas from Able’s land, so the proceeds
from the plant are the proceeds from the wells on the lease, and so Able should be 1/8th of $2.20.
(B)  What price is used to value Baker’s royalty?
Answer: Baker’s gas is sold off the lease, so Baker will get 1/8th of whatever the market value at
the well is determined to be, minus 20 cents. Baker’s royalty will be subject to deductions for
post-production costs, unlike Able’s royalty, but it will be based on current market value of gas
regardless of gross proceeds from the sale of the gas.
9 Royalty Clauses: Market Value vs. Proceeds
Piney Woods Country Life School v. Shell Oil Co.
Piney Woods Country Life School v. Shell Oil Co., 726 F.2d 225:
1.  Facts
2.  Court reasoning
“We conclude that the purpose is to distinguish between gas sold in the form in which it emerges
from the well, and gas to which value is added by transportation away from the well or by
processing after the gas is produced. The royalty compensates the lessor for the value of the gas at
the well; that is, the value of the gas after the lessee fulfills its obligation under the lease to
produce gas at the surface, but before the lessee adds to the value of this gas by processing or
transporting it. When the gas is sold at the well, the parties to the lease accept a good-faith sale
price as the measure of the value at the well. But when the gas is sold for a price that reflects
value added to the gas after production, the sale price will not necessarily reflect the market value
of the gas at the well. Accordingly, the lease bases the royalty for this gas not on actual proceeds
but on market value.
“At the well” therefore describes not only location but quality as well. Market value at
the well means market value before processing and transportation, and gas is sold at the well if the
price paid is consideraton for the gas as produced but not for processing and transportation.”
10 Royalty Clauses: Market Value vs. Proceeds
Yzaguirre v. KCS Resources, Inc.
Yzaguirre v. KCS Resources, Inc., 53 S.W.3d 368:
1.  Facts
2.  Court reasoning
“Market value is the prevailing market price at the time of delivery and is not affected by a price
set at the time the lessee enters into a long-term sales contract with the buyer.”
11 Royalty Clauses: Market Value vs. Proceeds
Heritage Resources, Inc. v. Nationsbank
Heritage Resources, Inc. v. Nationsbank, 939 S.W.2d 118:
1.  Facts
(b) on gas . . . sold or used off the premises or in the manufacture of gasoline or other products
therefrom, the market value at the well of 1/5 of the gas so sold or used, provided, however, that
there shall be no deductions from the value of the Lessor’s royalty by reason of any required
processing, cost of dehydration, compression, transportation or other matter to market such gas.
2.  Court reasoning
“Market value at the well has a commonly accepted meaning in the oil and gas industry. Market
value is the price a willing seller obtains from a willing buyer. There are two methods to
determine market value at the well.
The most desirable method is to use comparable sales. A comparable sale is one that is
comparable in time, quality, quantity, and availability of marketing outlets.
Courts use the second method when information about comparable sales I not readily
available. This method involves subtracting reasonable post-production marketing costs from the
market value at the point of sale. Post-production marketing costs include transporting the gas to
the market and processing the gas to make it marketable. With either method, the plaintiff has the
burden to prove market value at the well.”
12 Oil & Gas
Gas
Lease
Sales Contract
1/8th of Market Value at the Well
e as e
Does the intercompany price
L
f
f
O
d
Royalty Clause
Use
represent the best possible price?
r
o
d
in lease says: Sol
(Yzaguirre)
Sold “At th
e Well” 1/8th of Amount Realized (proceeds)
“On the P
Does the intercompany price
remises”
represent market? (Amoco v.
Frist Baptist Church)
•  Gas is sold produced when it is extracted from the ground
•  Gas is sold when it is delivered
•  Gas is delivered, sold, and produced at the same time in one continuous flow
•  Market Value equals market price at the time of sale/production/delivery
•  So, market value
long term contract price; gas is not sold when long-term
contract is signed. Much of the gas can be stored for years.
•  Both Prongs allow lessee to deduct post-production costs because of “at the well.”
•  “To determine market value, gas should be valued as though it were free and
available for sale. Market value is the prevailing market price at the time of
delivery and is not affected by a price set at the time the lessee enters into a 13 long-
Royalty Clauses: “Market Value At the Well”
Chesapeake v. Hyder
Chesapeake v. Hyder, 427 S.W.3d 472:
1.  Facts
Lessee covenants and agrees to pay Lessor the following royalty: (a) twenty-five percent (25%) of the
market value at the well of all oil and other liquid hydrocarbons produced and saved from the Leased
Premises as of the day it is produced and stored; and (b) for natural gas, including casinghead gas and
other gaseous substances produced from the Leased Premises and sold or used on or off the Leased
Premises, twenty-five percent (25%) of the price actually received [note: not Market Value at the Well]
by [appellants] for such gas .... The royalty reserved herein by [appellees] shall be free and clear of all
production and post-production costs and expenses, including but not limited to, production,
gathering, separating, storing, dehydrating, compressing, transporting, processing, treating, marketing,
delivering, or any other costs and expenses incurred between the wellhead and [appellant’s] point of
delivery or sale of such share to a third party. In no event shall the volume of gas used to calculate
Lessors' royalty be reduced for gas used by Lessee as fuel for lease operations or for compression or
dehydration of gas. ... Lessors and Lessee agree that the holding in the case of Heritage Resources,
Inc. v. Nationsbank, 939 S.W.2d 118 (Tex. 1996) shall have no application to the terms and
provision of this Lease.
2.  Court reasoning
The parties modified the general rule by agreement, and we interpret the parties’ agreement as the
royalty clause excluding all costs and expenses of production and post-production, including postproduction costs and expenses incurred between the point of delivery and the point of sale. Our
conclusion is reinforced by the parties’ agreement that the holding in Heritage—that the measure of the
“value of the Lessor’s royalty” required a deduction for post-production costs, and therefore, the leases’
“no deduct” provision was “surplusage as a matter of law”—did not apply to the
14 terms and provisions of the Hyder lease.
Royalty Clauses: “Market Value At the Well”
Chesapeake v. Hyder
Wellhead
Central Hub
Interstate Pipeline
Gathering Lines
Chesapeake Operating,
Inc. (“COI”)
Lessee/Operator
Sells gas
Chesapeake Energy
Manufacturing (“CEMI”)
“at the wellhead” Distributor/Marketer
@$3
f
c
80 m
10 mcf @$4
Sells gas at
Various delivery points
(WASP=$3.30)
Customer #1
Customer #2
Customer #3
Chesapeake Midstream
Partners, L.P. (“CMP”)
Gas Handler
15 Royalty Clauses: Chesapeake v. Hyder
Overriding Royalty Clause
The overriding royalty clause provided as follows:
“a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent
(5.0%) of gross production obtained”
5-4 decision stating that no post-production cost reduction. But, the Court has requested that the
Hyders file a reply to Chesapeake’s motion for rehearing and an amicus brief has been filed
claiming that “gross production” indicates at the wellhead.
Which opinion (majority or dissent) do you think is better?
Could the lease have been better drafted?
16 Royalty Clauses: “Market Value At the Well”
Hyder Review Problem #1
The royalty clause in a Texas lease states that Lessee is to pay royalties equal to:
"20% of the amount realized by Lessee, computed at the mouth of the well.” The lease
also contains an addendum, as follows:
Lease addendum: Notwithstanding anything to the contrary, herein contained, all royalty paid
to Lessor shall be free of all costs and expenses related to the exploration, production and
marketing of oil and gas production from the lease including, but not limited to, costs of
compression, dehydration, treatment and transportation. Lessor will, however, bear a
proportionate part of all those expenses imposed upon Lessee by its gas sale contract to the
extent incurred subsequent to those that are obligations of Lessee. It is expressly agreed
that the provisions of this Exhibit shall super[s]ede any portion of the printed form of this Lease
which is inconsistent herewith, and all other printed provisions of this Lease, to which this is
attached, are in all other things subrogated to the express and implied terms and conditions of
this Addendum.
1.  What result for Lessor?
2.  Where is point of valuation?
3.  Would you answer change if the lease also contained Hyder’s “anti-Heritage” language?
17 Royalty Clauses: “Market Value At the Well”
Hyder Review Problem #2 (2 Lease in Warren v. Chesapeake, 759 F.3d 413 (5
nd
th
Cir. 2014))
Suppose the lease provision included the same royalty provision of 20% of the "amount realized at
the mouth of the well." An Exhibit attached to the lease provided:
"Notwithstanding any of the provisions of the lease, royalties are to be calculated as the market
value at the point of sale of 20% of the gas so sold. Notwithstanding anything to the contrary herein,
all royalty paid to Lessor shall be free of all costs and expenses related to the exploration,
production and marketing of oil and gas production from the lease including, but not limited to, costs
of compression, dehydration, treatment and transportation.”
What result for Lessor?
18 Royalty Clauses: “Market Value At the Well”
Hyder Review Problem #3 (Potts v. Chesapeake, 760 F.3d 470 (5 Cir. 2014))
th
Suppose the royalty clause states as follows:
"Royalties to be paid by Lessee are: . . . on gas, the market value at the point of sale of 1/4 of the
gas sold. . . .Notwithstanding anything to the contrary herein, all royalty paid to Lessor shall be free
of all costs and expenses related to the exploration, production and marketing of oil and gas
production from the lease including, but not limited to, costs of compression, dehydration, treatment
and transportation.”
"Payments of royalties to Lessor shall be made monthly and shall be based on sales of oil and gas
to unrelated third parties at prices arrived at through arms length negotiations. Royalties to Lessor
on oil and gas not sold in an arms length transaction shall be determined based on
prevailing market values at the time in the area. Lessee shall have the obligation to disclose to
Lessor any information pertinent to this determination.”
Chesapeake Operating, Inc. (COI) sells the gas produced from the lease to Chesapeake
Energy Marketing, Inc. (CEMI) at the wellhead. CEMI transports the gas through a gathering
system, sends it through interstate pipelines, and resells it to various unaffiliated purchasers. CEMI
pays Chesapeake Exploration and COI the weighted average sales price (WASP) that CEMI
receives from these third-party purchasers, after deducting post-production costs incurred between
the wellhead and the sales points to third-party purchasers. Chesapeake Exploration pays Lessor
1/4 of the price received from CEMI. In other words, Chesapeake, as Lessee, accounts for
royalties using a "netback" value: Gross revenues received from third-party purchasers, minus
costs incurred from the wellhead to the sales point where the third-party took title to the gas.
Lessors claim that the deductions are not allowed under the lease terms. Are
19 they?
Royalty Clauses: Implied Covenant to Market
Amoco Production Co. v. First Baptist Church of Pyote
Amoco Production Co. v. First Baptist Church of Pyote, 579 S.W.2d 280:
1.  Facts
2.  Court reasoning
“In this case, Amoco by dedicating additional leases, including those of the Appellees herein, in
June, 1975, obtained an increased price for gas already dedicated under the prior contract from 17
to 70 cents per MCF. This was obviously a substantial benefit for Amoco and its royalty owners
under the previously dedicated leases. But it also meant that as to twelve of the leases involved in
this case, the royalty owners would receive a payment for gas which was approximately ½ of the
amount soon to be paid by Lone Star and Delhi, and with a very limited provision for future
acceleration. This was not a substantial benefit to them as compared to other royalty owners
whose gas was soon to be purchased by Lone Star and Delhi.”
20 Royalty Clauses: Implied Covenant to Market
Cook v. Tompkins
Cook v. Tompkins, 713 S.W.2d 417:
1.  Facts
2.  Court Holding:
a)  A lessee’s implied duty to market does not include a duty to notify purchasers of the address
of the lessor
b)  The implied duty to market does not include the duty to pay royalties in the event that the
purchaser does not pay them.
c)  Tompkins satisfied the implied duty to market by arranging for the sale of the oil at the posted
price on the customary terms in the area.
21 Royalty Clauses: Implied Covenant to Market
Parker v. TXO Production Corp. & Delhi Gas Pipeline
Park v. TXO Production Corp. & Delhi Gas Pipeline Corp, 716 S.W.2d 644:
1.  Facts
2.  Court Reasoning:
We agree with appellants that the sale of gas from Texas to its subsidiary is inherently suspect. The
record reflects that at the time of Texas' sale of the gas to Delhi, the other pipelines were offering
the maximum legal rate for natural gas. Delhi also offered this maximum price, but then deducted
a five percent compression charge, while the other prospective purchasers did not make such a
deduction. The net effect of the compression charge was to reduce the price Texas (and hence its
royalty interest holders) received to ninety-five percent of the going rate.
We do not agree, however, that this fact alone means that Texas breached its implied covenant to
market. In its per curiam opinion denying writ in the El Paso Court of Appeals' Pyote decision, the
Supreme Court stated that “[a]lthough in a proper factual setting, failure to sell at market value
may be relevant evidence of a breach of the covenant to market in good faith, it is merely
probative and is not conclusive.” Thus, other factors must be examined when deciding whether
Texas has breached its implied covenant with the appellants.
22 Royalty Clauses: Implied Covenant to Market
Texas Oil and Gas Corp. v. Hagen
Texas Oil and Gas Corp. v. Hagen, 1987 WL 47847:
1.  Facts
2.  Court Reasoning:
“Having determined the standard of conduct required of Texas lessees in fulfilling their marketing
obligations, the issue becomes whether there is any evidence that TXO has failed to meet this
standard. An oil and gas lessee breaches the implied covenant to reasonably market gas if the
lessee fails to obtain terms in the gas sales contract that a reasonably prudent operator would have
obtained. In light of the fact that the purchaser was a subsidiary, a prudent operator would have
secured for itself and its lessors the right to receive sulphur royalties and would have reserved the
right to renegotiate the contract price should the market value of the gas escalate. Indeed, TXO
recognized such a duty when it entered into voluntary price redeterminations with Delhi on several
occasions. We hold that there is evidence that TXO, as lessee, has failed to act as a reasonably
prudent operator would have acted under the same or similar circumstances.”
23 Royalty Clauses: Implied Covenant to Market
Cabot Co. v. Brown
Cabot Co. v. Brown, 1987 WL 47847:
1.  Facts
2.  Court of Appeals Reasoning (716 S.W.2d 656):
“Appellee sought to prove intrastate market value, not interstate value. The issue of interstate
value was, therefore, a defensive issue which appellant had the burden to submit at trial or bear the
consequences of a deemed finding in support of the judgment. The gas produced from the leases
in question were sold within Texas. While evidence of interstate gas price regulation may be
admissible, such evidence does not bind the fact finder as a matter of law in its determination of
market value.”
24 Division Orders:
Gavenda v. Strata Energy, Inc.
Gavenda v. Strate Energy, Inc., 705 S.W.2d 690:
1.  Facts
2.  Court Reasoning:
“When the operator, however, prepared erroneous orders and retained the benefits, we held that
division orders were not binding. In Terrell, Stanolind Oil & Gas prepared the division orders and
distributed the bonus and royalty accordingly. Stanolind Oil & Gas deducted the gross production
tax from the bonus, although the lease provided that there would be no deductions. Despite the
lease provision, Stanolind was shifting the gross production tax from itself to Terrell. It was
profiting from its own error in drawing up the division order. There was unjust enrichment.
Applying the law to this case, we hold that the division and transfer orders do not bind any of the
Gavendas. Strata both erroneously prepared the division and transfer orders and distributed the
royalties. Because of its error, Strata underpaid the Gavenda family by 7/16th royalty, retaining
part of the 7/16th royalty for itself. It profited, unlike the operators in Exxon v. Middleton, at the
royalty owner’s expense. It retained for itself, unlike in Chicago Cop. V. Wall, part of the proceeds
owned to the royalty owners. Therefore, Strata is liable to the Gavendas for whatever portion of
their royalties it retained, although it is not liable to the Gavendas for any of their royalties paid
out to various overriding or other royalty owners.”
25 Division Order Statutes:
§91.402 of the Texas Natural Resources Code:
(d)
THIS AGREEMENT DOES NOT AMEND ANY LEASE OR OPERATING AGREEMENT
BETWEEN THE INTEREST OWNERS AND THE LESSEE OR OPERATOR OR ANY OTHER
CONTRACTS FOR THE PURCHASE OF OIL OR GAS.
(g)  Division orders are binding for the time and to the extent that they have been acted on and made the
basis of settlements and payments, and, from the time that notice is given that settlements will not be
made on the basis provided in them, they cease to be binding. Division orders are terminable by either
party on 30 days written notice.
(h)
The execution of a division order between a royalty owner and lessee or between a royalty owner and a
party other than lessee shall not change or relieve the lessee’s specific, expressed or implied obligations
under an oil and gas lease, including any obligation to market production as a reasonable prudent lessee.
Any provision of a division order between payee and its lessee which is in contradiction with any
provision of an oil and gas lease is invalid to the extent of the contradiction.
(i)
A division order may be used to clarify royalty settlement terms in the oil and gas lease. With respect to
oil and/or gas sold in the field where produced or at a gathering point in the immediate vicinity, the
terms “market value,” “market price,” “prevailing price in the field,” or other such language, when used
as a basis of valuation in the oil and gas lease, shall be defined as the amount realized at the mouth of
the well by the seller of such prodution in an arm’s-length transaction.
26 Division Order Statutes:
Ohrt v. Union Gas Co.
Lessee drilled a well on the Lessor's tract and then pooled this tract with other acreage.
Pooling clause allowed poolig of 320 acres but lessee pooled 690 acres in excess of
what was authorized. Lessee sent D/O to Lessors showing the size of the unit (690
acres) and its effective date as the date of first production. Lessors signed the D/Os
certifying their ownership of this pooled share of royalties. Lessee sent royalty checks
calculated on the basis of the signed D/Os and Lessors cashed them every month.
Lessors then realize that lease did not authorize pooling and demanded 100% of
royalties from the date of production though January 14, 2001, the day before the
Pooling Designation was filed of record. These 4 months of production amounted to
$838,400 of underpaid royalties (stipulated by all parties).
Held: Lessor had ratified and waived claims for these past royalties and was also
estopped from claiming them. A jury had so found, and the judge affirmed the jury's
answers to these issues.
The rationale was simple: Lessor had signed D/Os and accepted royalties based on the
Lessee's calculations, and subsection (g) of the D/O Act makes D/Os binding until
revoked.
27 Take or Pay and Royalty Owners:
Problem 7-70:
Assume that Pipeline Opossum has negotiated with Producer Pete to buy out the TOP
provision in the Gas Purchase Agreement which governs all the gas sold in the Black gold
field in Texas. In return, Producer Pete received a $20 million settlement from Pipeline
Oppossum of all TOP liabilities. The royalty owners who signed leases with Producer Pete
in this field hear about the settlement. They would like to receive 1/8 of the $20 million
TOP settlement.
Questions:
1.  Who wins and why?
2.  Suppose that the Royalty Interest Owners signed a division order that expressly provided
for a share of any TOP proceeds or settlements received by the lessee to be paid to the
lessors. Can a lessee invoke the Division Order Act and object to the language in the
division order because it contradicts the lease?
28